-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, T9No3yjzonYcw4bTUaZ4qhdrXofSj/jQfYo0trD+fZBo0Hj3GX79ihP8wpc1L67C 6r2bIpUhJvVVdKwD8EUZpA== 0000003153-01-500007.txt : 20010308 0000003153-01-500007.hdr.sgml : 20010308 ACCESSION NUMBER: 0000003153-01-500007 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20010228 ITEM INFORMATION: FILED AS OF DATE: 20010306 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ALABAMA POWER CO CENTRAL INDEX KEY: 0000003153 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 630004250 STATE OF INCORPORATION: AL FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 001-03164 FILM NUMBER: 1561888 BUSINESS ADDRESS: STREET 1: 600 N 18TH ST STREET 2: P O BOX 2641 CITY: BIRMINGHAM STATE: AL ZIP: 35291 BUSINESS PHONE: 2052571000 8-K 1 ala_8k.txt SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported) February 28, 2001 ----------------------------- ALABAMA POWER COMPANY - ------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) Alabama 1-3164 63-0004250 - ------------------------------------------------------------------------------- (State or other jurisdiction (Commission (IRS Employer of incorporation) File Number) Identification No.) 600 North 18th Street, Birmingham, Alabama 35291 - ------------------------------------------------------------------------------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (205) 257-1000 -------------------------- N/A - ------------------------------------------------------------------------------- (Former name or former address, if changed since last report.) Item 7. Financial Statements and Exhibits. (c) Exhibits. 23 - Consent of Arthur Andersen LLP. 99 - Audited Financial Statements of Alabama Power Company as of December 31, 2000. SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. ALABAMA POWER COMPANY By /s/ Wayne Boston Wayne Boston Assistant Secretary Date: March 6, 2001 EX-23 2 ala_ex23.txt ARTHUR ANDERSEN Exhibit 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report dated February 28, 2001 on the financial statements of Alabama Power Company, included in this Form 8-K, into Alabama Power Company's previously filed Registration Statement File No. 333-67453. /s/Arthur Andersen LLP Birmingham, Alabama February 28, 2001 EX-99 3 ala_ex99.txt MANAGEMENT'S REPORT Alabama Power Company 2000 Annual Report The management of Alabama Power Company has prepared -- and is responsible for - -- the financial statements and related information included in this report. These statements were prepared in accordance with accounting principles generally accepted in the United States and necessarily include amounts that are based on the best estimates and judgments of management. Financial information throughout this annual report is consistent with the financial statements. The Company maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that the accounting records reflect only authorized transactions of the Company. Limitations exist in any system of internal controls, however, based on a recognition that the cost of the system should not exceed its benefits. The Company believes its system of internal accounting controls maintains an appropriate cost/benefit relationship. The Company's system of internal accounting controls is evaluated on an ongoing basis by the Company's internal audit staff. The Company's independent public accountants also consider certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on the financial statements. The audit committee of the board of directors, composed of independent directors, provides a broad overview of management's financial reporting and control functions. Periodically, this committee meets with management, the internal auditors and the independent public accountants to ensure that these groups are fulfilling their obligations and to discuss auditing, internal controls, and financial reporting matters. The internal auditors and independent public accountants have access to the members of the audit committee at any time. Management believes that its policies and procedures provide reasonable assurance that the Company's operations are conducted according to a high standard of business ethics. In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations and cash flows of Alabama Power Company in conformity with accounting principles generally accepted in the United States. /s/Elmer B. Harris Elmer B. Harris President and Chief Executive Officer /s/William B. Hutchins, III William B. Hutchins, III Executive Vice President, Chief Financial Officer, and Treasurer 1 REPORT OF INDEPENDENT PUBLIC ACCOUNTANT To Alabama Power Company: We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (an Alabama corporation and a wholly owned subsidiary of Southern Company) as of December 31, 2000 and 1999, and the related statements of income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements (pages 12-30) referred to above present fairly, in all material respects, the financial position of Alabama Power Company as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. /s/Arthur Andersen LLP Birmingham, Alabama February 28, 2001 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Alabama Power Company 2000 Annual Report RESULTS OF OPERATIONS Earnings Alabama Power Company's 2000 net income after dividends on preferred stock was $420 million, representing a $20 million (5 percent) increase from the prior year. This improvement is primarily attributable to an increase in territorial sales partially offset by increased non-fuel operating expenses. In 1999, earnings were $400 million, representing a 6 percent increase from the prior year. This increase was due to a decrease in amortization related to premiums paid to reacquire debt pursuant to an Alabama Public Service Commission (APSC) order. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional details. The return on average common equity for 2000 was 13.58 percent compared to 13.85 percent in 1999, and 13.63 percent in 1998. Revenues Operating revenues for 2000 were $3.7 billion, reflecting an increase from 1999. The following table summarizes the principal factors that have affected operating revenues for the past two years: Increase (Decrease) Amount From Prior Year ---------------------------------------- 2000 2000 1999 - ------------------------------------------------------------------- (in thousands) Retail -- Base revenues $2,108,939 $ 80,264 $ 10,022 Fuel cost recovery and other 843,768 61,326 20,418 - ------------------------------------------------------------------- Total retail 2,952,707 141,590 30,440 - ------------------------------------------------------------------- Sales for resale -- Non affiliates 461,730 46,353 (33,596) Affiliates 166,219 73,780 (11,123) - ------------------------------------------------------------------- Total sales for resale 627,949 120,133 (44,719) Other operating revenues 86,805 20,264 13,380 - ------------------------------------------------------------------- Total operating revenues $3,667,461 $281,987 $ (899) =================================================================== Percent change 8.33% (0.03)% - -------------------------------------------------------------------- Retail revenues of $3.0 billion in 2000 increased $142 million (5 percent) from the prior year, compared with an increase of $30 million (1.1 percent) in 1999. The primary contributors to the increase in revenues in 2000 were the positive impact of weather on energy sales, continued economic growth in the Company's service territory, and an increase in fuel revenues. Fuel revenues have no effect on net income because they represent the recording of revenues to offset fuel expenses, including the fuel component of purchased energy. Fuel rates billed to customers are designed to fully recover fluctuating fuel costs over a period of time. Higher natural gas prices and decreased hydro production combined with increased costs of purchased power have resulted in a large under-recovery of fuel costs at December 31, 2000. Effective January 2001, the Company's fuel rate was increased to address this under-recovery. The Company expects to significantly reduce this balance over a three-year period. 3 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report The $20 million (30.5 percent) increase in other operating revenues in 2000 as compared to 1999 was due primarily to an increase in steam sales in conjunction with the operation of the Company's co-generation facilities. Retail revenues in 1999 increased $30 million (1.1 percent) over 1998. The predominant factors causing the rise in revenues in 1999 were continued growth in the Company's service territory, as well as an increase in fuel revenues. These increases were offset by the effect of milder temperatures in 1999 as compared to 1998. Energy sales for resale outside the service area are predominantly unit power sales under long-term contracts to Florida utilities. Economy energy and energy sold under short-term contracts are also sold for resale outside the service area. Revenues from long-term power contracts have both a capacity and energy component. Capacity revenues reflect the recovery of fixed costs and a return on investment under the contracts. Energy is generally sold at variable cost. These capacity and energy components of the unit power contracts were as follows: 2000 1999 1998 --------------------------------------- (in millions) Capacity $127 $122 $142 Energy 128 112 118 -------------------------------------------------------- Total $255 $234 $260 ======================================================== Capacity revenues from non-affiliates were relatively unchanged in 2000 compared to the prior year. Capacity revenues from non-affiliates in 1999 decreased 13.9 percent compared to 1998. This decrease was attributable to the lowering of the equity return under formula rate contracts, as well as other adjustments and true-ups related to contractual pricing. Revenues from sales to affiliated companies within the Southern electric system, as well as purchases of energy, will vary from year to year depending on demand and the availability and cost of generating resources at each company. These transactions did not have a significant impact on earnings. Kilowatt-hour (KWH) sales for 2000 and the percent change by year were as follows: KWH Percent Change -------------------------------------- 2000 2000 1999 -------------------------------------- (millions) Residential 16,772 6.8% (0.6)% Commercial 12,989 5.5 3.4 Industrial 22,101 0.7 1.7 Other 206 2.3 2.3 ------------ Total retail 52,068 3.8 1.4 Sales for resale - Non-affiliates 14,848 19.4 5.0 Affiliates 5,369 6.7 (15.8) ------------ Total 72,285 6.9% 0.5% - --------------------------------------------------------------- The increases in 2000 and 1999 retail energy sales were primarily due to the strength of business and economic conditions in the Company's service area. In 2000, residential energy sales experienced a 6.8 percent increase over the prior year primarily as a result of warmer summer temperatures and cold winter weather conditions compared to 1999. Assuming normal weather, sales to retail customers are projected to grow approximately 2.9 percent annually on average during 2001 through 2005. Expenses In 2000, total operating expenses of $2.7 billion were up $235 million or 9.4 percent compared with the prior year. This increase was mainly due to a $183 million increase in fuel and purchased power costs, accompanied by a $23 million increase in maintenance expenses. In 1999, total operating expenses of $2.5 billion decreased $13 million or 0.5 percent compared with 1998. This decline was mainly due to a $15 million net decrease in fuel and purchased power costs and a $23 million decrease in maintenance expense, offset by an increase in taxes other than income taxes of $12 million. 4 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report Fuel costs constitute the single largest expense for the Company. The mix of fuel sources for generation of electricity is determined primarily by system load, the unit cost of fuel consumed, and the availability of hydro and nuclear generating units. The amount and sources of generation and the average cost of fuel per net KWH generated were as follows: -------------------------- 2000 1999 1998 -------------------------- Total generation (billions of KWHs) 65 63 63 Sources of generation (percent) -- Coal 72 72 72 Nuclear 19 20 18 Hydro 3 5 8 Oil & Gas 6 3 2 Average cost of fuel per net KWH generated (cents) -- 1.54 1.44 1.54 - -------------------------------------------------------------- In 2000, total fuel and purchased power costs of $1.3 billion increased $183 million (16 percent), while total energy sales increased 4,658 million kilowatt hours (6.9 percent) compared with the amounts recorded in 1999. Fuel and purchased power costs in 1999 decreased $15 million (1 percent) compared to 1998. Purchased power consists of purchases from affiliates in the Southern electric system and non-affiliated companies. Purchased power transactions among the Company and its affiliates will vary from period to period depending on demand, the availability, and the variable production cost of generating resources at each company. During 2000, purchased power transactions among the Company and non-affiliates increased $72 million (77 percent) due to higher costs associated with these energy purchases and to offset decreased hydro generation, which was down significantly compared to 1999 as a result of lower stream flows. The 8.4 percent increase in maintenance expense in 2000 as compared to 1999 is primarily attributable to an increase in the maintenance of overhead distribution lines and additional accruals to partially replenish the natural disaster reserve. The 7.5 percent decrease in maintenance expenses in 1999 is primarily attributable to a decrease in distribution expenses. Depreciation and amortization expense increased 4.9 percent in 2000 and 2.6 percent in 1999. These increases reflect additions to property, plant, and equipment. Taxes other than income taxes increased $5 million (2.5 percent) in 2000 as compared to 1999. This increase is attributable to increases in real and personal property taxes and public utility license taxes. Total net interest and other charges increased $7 million (2.7 percent) in 2000. This increase results primarily from an increase in interest on long-term debt offset by a decrease in other interest charges. Total net interest and other charges decreased $38 million (12.3 percent) in 1999 primarily from a decrease in the amortization of premiums on reacquired debt pursuant to an APSC order. See Note 3 to the financial statements under "Retail Rate Adjustment Procedures" for additional details. Effects of Inflation The Company is subject to rate regulation and income tax laws that are based on the recovery of historical costs. Therefore, inflation creates an economic loss because the Company is recovering its costs of investments in dollars that have less purchasing power. While the inflation rate has been relatively low in recent years, it continues to have an adverse effect on the Company because of the large investment in utility plant with long economic lives. Conventional accounting for historical cost does not recognize this economic loss nor the partially offsetting gain that arises through financing facilities with fixed-money obligations, such as long-term debt and preferred securities. Any recognition of inflation by regulatory authorities is reflected in the rate of return allowed. Future Earnings Potential The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of future earnings depends on numerous factors. The major factor is the ability of the Company to achieve energy sales growth while containing cost in a more competitive environment. The Company currently operates as a vertically integrated utility providing electricity to customers within its traditional service area located in the 5 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report state of Alabama. Prices for electricity provided by the Company to retail customers are set by the APSC under cost-based regulatory principles. Future earnings for the traditional business in the near term will depend upon growth in energy sales, which is subject to a number of factors. These factors include weather, competition, new short and long-term contracts with neighboring utilities, energy conservation practiced by customers, the elasticity of demand, and the rate of economic growth in the Company's traditional service area. The electric utility industry in the United States is continuing to evolve as a result of regulatory and competitive factors. Among the primary agents of change has been the Energy Policy Act of 1992 (Energy Act). The Energy Act allows independent power producers (IPPs) to access a utility's transmission network in order to sell electricity to other utilities. This enhances the incentive for IPPs to build cogeneration plants for a utility's large industrial and/or commercial customers and sell excess energy generation to other utilities. Also, electricity sales for resale rates are affected by wholesale transmission access and numerous potential new energy suppliers, including power marketers and brokers. Although the Energy Act does not permit retail customer access, it was a major catalyst for the current restructuring and consolidation taking place within the utility industry. Numerous federal and state initiatives are in varying stages to promote wholesale and retail competition. Among other things, these initiatives allow customers to choose their electricity provider. Some states have approved initiatives that result in a separation of the ownership and/or operation of generating facilities from the ownership and/or operation of transmission and distribution facilities. While various restructuring and competition initiatives have been discussed in Alabama, none have been enacted. In October 2000, the APSC completed a two-year study of electric industry restructuring, concluding that (i) restructuring of the electric utility industry in Alabama was not in the public interest and (ii) the APSC itself would not mandate retail competition or electric industry restructuring without enabling state legislation. Electric utility restructuring would require numerous issues to be resolved, including significant ones relating to recovery of any stranded investments, full cost recovery of energy produced, and other issues related to the current energy crisis in California. As a result of this crisis, many states have either discontinued or delayed implementation of initiatives involving retail deregulation. The inability of the Company to recover its investments, including the regulatory assets described in Note 1 to the financial statements, could have a material adverse effect on the Company's financial statements. Continuing to be a low-cost producer could provide opportunities to increase market share and profitability in markets that evolve with changing regulation. Conversely, if the Company does not remain a low-cost producer and provide quality service, then energy sales growth could be limited, and this could significantly erode earnings. On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued its final rule on Regional Transmission Organizations (RTOs). The order encouraged utilities owning transmission systems to form RTOs on a voluntary basis. After participating in the regional conferences with customers and other members of the public to discuss the formation of RTOs, utilities were required to make a filing with the FERC. Southern Company and its integrated southeast utility subsidiaries, including the Company, filed on October 16, 2000, a proposal for the creation of an RTO. The proposal is for the formation of a for-profit company that would have control of the bulk power transmission system of the Company and any other participating utilities. Participants would have the option to either maintain their ownership, divest, sell, or lease their assets to the proposed RTO. If the FERC accepts the proposal as filed, the creation of an RTO is not expected to have a material impact on the Company's financial statements. The outcome of this matter cannot now be determined. The Energy Act amended the Public Utility Holding Company Act of 1935 (PUHCA) to allow holding companies to form exempt wholesale generators to sell power largely free of regulation under PUHCA. These entities are able to own and operate power generating facilities and sell power to affiliates--under certain restrictions. The Company is constructing 1,230 megawatts of wholesale generating facilities in Autaugaville, Alabama to begin operation in 2003. Half of this 6 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report capacity has been certified by the APSC to serve the Company's retail customers for seven years. The other half of the capacity will be sold into the wholesale market and will not affect retail rates. Southern Company is aggressively working to maintain and expand its share of wholesale sales in the southeastern power markets. In January 2001, Southern Company announced the formation of a new subsidiary--Southern Power Company (SPC). The new subsidiary will own, manage, and finance wholesale generating assets in the Southeast. SPC will be the primary growth engine for Southern Company's market-based energy business. Energy from its assets will be marketed to wholesale customers under the Southern Company name. Currently, the Company plans to transfer the generating facilities under construction in Autaugaville to SPC in 2001. The Company will enter into a purchased power agreement for half of the capacity of these generating facilities to serve its territorial customers. In accordance with Financial Accounting Standards Board (FASB) Statement No. 87, Employers' Accounting for Pensions, the Company recorded non-cash income of approximately $54 million in 2000. Pension plan income in 2001 is expected to be less as a result of plan amendments. Future pension income is dependent on several factors including trust earnings and changes to the plan. For more information, see Note 2. Rates to retail customers served by the Company are regulated by the APSC. Rates for the Company can be adjusted periodically within certain limitations based on earned retail rate of return compared with an allowed return. There is a moratorium on any periodic retail rate increases (but not decreases) until July 2001. In December 1995, the APSC issued an order authorizing the Company to reduce balance sheet items -- such as plant and deferred charges -- at any time the Company's actual base rate revenues exceed the budgeted revenues. In April 1997, the APSC issued an additional order authorizing the Company to reduce balance sheet asset items. This order authorizes the reduction of such items up to an amount equal to five times the total estimated annual revenue reduction resulting from future rate reductions initiated by the Company. In April 2000, the APSC approved an amendment to the Company's existing rate structure to provide for the recovery of retail costs associated with certified purchased power agreements. In November 2000, the APSC certified a seven-year purchased power agreement pertaining to 615 megawatts of the Company's wholesale generating facilities under construction in Autaugaville, Alabama, all of which will be delivered in 2003. In addition, the APSC certified a seven-year purchased power agreement with a third party for approximately 630 megawatts; one half of the power will be delivered in 2003 while the remaining half is scheduled for delivery in 2004. The Company is involved in various matters being litigated. See Note 3 to the financial statements for information regarding material issues that could possibly affect future earnings. Compliance costs related to current and future environmental laws and regulations could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed later under "Environmental Matters." The staff of the Securities and Exchange Commission (SEC) has questioned certain of the current accounting practices of the electric utility industry -- including the Company -- regarding the recognition, measurement, and classification in the financial statements of decommissioning costs for nuclear generating facilities. In response to these questions, the FASB is reviewing the accounting for liabilities related to the retirement of long-lived assets, including nuclear decommissioning. If the FASB issues new accounting rules, the estimated costs of retiring the Company's nuclear and other facilities may be required to be recorded as liabilities in the Balance Sheets. Also, the annual provisions for such costs could change. Because of the Company's current ability to recover asset retirement costs through rates, these changes would not have a significant adverse effect on results of operations. See Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning" for additional information. The Company is subject to the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. In the event that a portion of the Company's operations is no longer subject to these provisions, the Company would be required to write off related regulatory assets and 7 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report liabilities that are not specifically recoverable, and determine if any other assets have been impaired. See Note 1 to the financial statements under "Regulatory Assets and Liabilities" for additional information. New Accounting Standard In June 2000, FASB issued Statement No. 138, an amendment of Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. Statement No. 133, as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. Statement No. 133 requires that certain derivative instruments be recorded in the balance sheet as either an asset or liability measured at fair value, and that changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The Company utilizes financial instruments to reduce its exposure to changes in foreign currency exchange rates. The Company also enters into commodity related forward contracts to limit exposure to changing prices on certain fuel purchases and electricity purchases and sales. Substantially all of the Company's bulk energy purchases and sales meet the definition of a derivative under Statement No. 133. In many cases, these transactions meet the normal purchase and sale exception and the related contracts will continue to be accounted for under the accrual method. Certain of these instruments qualify as cash flow hedges resulting in the deferral of related gains and losses in other comprehensive income until the hedged transactions occur. Any ineffectiveness will be recognized currently in net income. However, others will be required to be marked to market through current period income. The Company adopted Statement No. 133 effective January 1, 2001, with no material impact. The application of the new rules is still evolving and further guidance from FASB is expected, which could additionally impact the Company's financial statements. Exposure to Market Risk Due to cost-based rate regulation, the Company has limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To mitigate residual risks relative to movements in electricity prices, the Company enters into fixed price contracts for the purchase and sale of electricity through the wholesale electricity market. Realized gains and losses are recognized in the income statement as incurred. At December 31, 2000, exposure from these activities was not material to the Company's financial position, results of operations, or cash flows. Also, based on the Company's overall interest rate exposure at December 31, 2000, a near-term 100 basis point change in interest rates would not materially affect the financial statements. FINANCIAL CONDITION Overview The Company's financial condition remained stable in 2000. This stability is the continuation over recent years of growth in retail energy sales and cost control measures combined with a significant lowering of the cost of capital, achieved through the refinancing and/or redemption of higher-cost long-term debt and preferred stock. The Company had gross property additions of $871 million in 2000. The majority of funds needed for gross property additions for the last several years have been provided from operating activities, principally from earnings and non-cash charges to income such as depreciation and deferred income taxes. The Statements of Cash Flows provide additional details. Capital Structure The Company's ratio of common equity to total capitalization -- including short-term debt -- was 42.2 percent in 2000 and 42.4 percent in 1999 and 1998. During 2000, the Company issued $250 million of senior notes, the proceeds of which were used primarily to repay short-term indebtedness. Capital Requirements Capital expenditures are estimated to be $735 million for 2001, $891 million for 2002, and $625 million for 2003. See Note 4 to the financial statements for additional details. 8 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report Actual construction costs may vary from estimates because of changes in such factors as: business conditions; environmental regulations; nuclear plant regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Other Capital Requirements The Company will continue to retire higher-cost debt and preferred stock and replace these obligations with lower-cost capital if market conditions permit. Environmental Matters In November 1990, the Clean Air Act Amendments (Clean Air Act) were signed into law. Title IV of the Clean Air Act -- the acid rain compliance provision of the law -- significantly affected the integrated Southeast utility subsidiaries of Southern Company, including the Company. Specific reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fired generating plants were required in two phases. Phase I compliance began in 1995 and some 50 generating plants within the operating companies of Southern Company were brought into compliance with Phase I requirements. Southern Company achieved Phase I sulfur dioxide compliance at the affected plants by switching to low-sulfur coal, which required some equipment upgrades. Construction expenditures for Phase I compliance totaled approximately $25 million for the Company. Phase II sulfur dioxide compliance was required in 2000. The Company used emission allowances and fuel switching to comply with Phase II requirements. Also, equipment to control nitrogen oxide emissions was installed on additional system fossil-fired units as necessary to meet Phase II limits. Compliance with Phase II increased total construction expenditures through 2000 by $63 million The one-hour ozone non-attainment standards for the Birmingham area have been set and must be implemented in May 2003. Two generating plants will be affected in the Birmingham area. Additional construction expenditures for compliance with these new rules are currently estimated at approximately $230 million. In July 1997, the Environmental Protection Agency (EPA), revised the national ambient air quality standards for ozone and particulate matter. This revision made the standards significantly more stringent. In the subsequent litigation of these standards, the U. S. Supreme Court recently dismissed certain challenges but found the EPA's implementation program for the new ozone standard unlawful and remanded it to the EPA. In addition, the Federal District of Columbia Circuit Court of Appeals will address other legal challenges to these standards in mid-2001. If the standards are eventually upheld, implementation could be required by 2007 to 2010. In September 1998, the EPA issued the final regional nitrogen oxide reduction rules to the states for implementation. Compliance is required by May 31, 2004. The final rule affects 21 states including Alabama. If standards and rules for implementation are upheld, the additional construction expenditures for compliance are estimated at approximately $189 million. A significant portion of costs related to the acid rain and ozone non-attainment provisions of the Clean Air Act is expected to be recovered through existing ratemaking provisions. However, there can be no assurance that all Clean Air Act costs will be recovered. On November 3, 1999, the EPA brought a civil action against the Company in the U. S. District Court. The complaint alleges violations of the prevention of significant deterioration and new source review provisions of the Clean Air Act with respect to coal-fired generating facilities at the Company's Plants Miller, Barry, and Gorgas. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The EPA concurrently issued a notice of violation to the Company relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The complaint and notice of violation are similar to those brought against and issued to several other electric utilities. The complaint and notice of violation allege that the Company had failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. On August 1, 2000, the U.S. District Court granted the Company's motion to dismiss for lack of jurisdiction in Georgia and granted the system service 9 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report company's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. On January 12, 2001, the EPA re-filed its claims against the Company in federal district court in Birmingham, Alabama. The EPA did not include the system service company in the new complaint. The Company believes that it complied with applicable laws and EPA regulations and interpretations in effect at the time the work in question took place. The Clean Air Act authorizes civil penalties of up to $27,500 per day per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates. In December 2000, the EPA completed its utility studies for mercury and other hazardous air pollutants (HAPS) and issued a determination that an emission control program for mercury and perhaps, other HAPS is warranted. The program is to be developed over the next four years under the Maximum Achievable Control Technology (MACT) provisions of the Clean Air Act. This determination is being challenged in the courts. In January 2001, the EPA proposed guidance for the determination of Best Available Retrofit Technology (BART) emission controls under the Regional Haze Regulations. Installation of BART controls would likely be required around 2010. Litigation of the BART rules is probable in the near future. Implementation of the final state rules for these initiatives could require substantial further reductions in nitrogen oxide, sulfur dioxide, mercury, and other HAPS emissions from fossil-fired generating facilities and other industries in these states. Additional compliance costs and capital expenditures resulting from the implementation of these rules and standards cannot be determined until the results of legal challenges are known, and the states have adopted their final rules. Reviews by the new administration in Washington, D.C. add to the uncertainties associated with BART guidance and the MACT determination for mercury and other HAPS. The EPA and state environmental regulatory agencies are reviewing and evaluating various other matters including: control strategies to reduce regional haze; limits on pollutant discharges to impaired waters; water intake restrictions; and hazardous waste disposal requirements. The impact of any new standards will depend on the development and implementation of applicable regulations. The Company must comply with other environmental laws and regulations that cover the handling and disposal of hazardous waste. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup costs and will recognize in the financial statements costs to clean up known sites. The Company has not incurred any cleanup costs to date. Several major pieces of environmental legislation are being considered for reauthorization or amendment by Congress. These include: the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; and the Endangered Species Act. Changes to these laws could affect many areas of the Company's operations. The full impact of any such changes cannot be determined at this time. Compliance with possible additional legislation related to global climate change, electromagnetic fields, and other environmental and health concerns could significantly affect the Company. The impact of new legislation -- if any - -- will depend on the subsequent development and implementation of applicable regulations. In addition, the potential exists for liability as the result of lawsuits alleging damages caused by electromagnetic fields. Sources of Capital The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from internal sources. However, the type and timing of any financings - if needed - will depend on market conditions and regulatory approval. In recent years, financings primarily have utilized unsecured debt and trust preferred securities. 10 MANAGEMENT'S DISCUSSION AND ANALYSIS (continued) Alabama Power Company 2000 Annual Report As required by the Nuclear Regulatory Commission and as ordered by the APSC, the Company has established external trust funds for nuclear decommissioning costs. In 1994, the Company also established an external trust fund for postretirement benefits as ordered by the APSC. The cumulative effect of funding these items over a long period will diminish internally funded capital and may require capital from other sources. For additional information concerning nuclear decommissioning costs, see Note 1 to the financial statements under "Depreciation and Nuclear Decommissioning." Cautionary Statement Regarding Forward-Looking Information This Annual Report includes forward-looking statements in addition to historical information. Forward-looking information includes, among other things, statements concerning projected retail sales growth and scheduled completion of new generation. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "should," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "potential" or "continue" or the negative of these terms or other comparable terminology. The Company cautions that there are various important factors that could cause actual results to differ materially from those indicated in the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include the impact of recent and future federal and state regulatory change, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and also changes in environmental and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations; current and future litigation, including the pending EPA civil action against the Company; the extent and timing of the entry of additional competition in the markets of the Company; potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial; internal restructuring or other restructuring options, that may be pursued by the Company; state and federal rate regulation in the United States; political, legal and economic conditions and developments in the United States; financial market conditions and the results of financing efforts; the impact of fluctuations in commodity prices, interest rates and customer demand; weather and other natural phenomena; the ability of the Company to obtain additional generating capacity at competitive prices; and other factors discussed elsewhere herein and in other reports (including Form 10-K) filed from time to time by the Company with the SEC. 11 STATEMENTS OF INCOME For the Years Ended December 31, 2000, 1999, and 1998 Alabama Power Company 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------- 2000 1999 1998 - ----------------------------------------------------------------------------------------------------------------------------- (in thousands) Operating Revenues: Retail sales $2,952,707 $2,811,117 $2,780,677 Sales for resale -- Non-affiliates 461,730 415,377 448,973 Affiliates 166,219 92,439 103,562 Other revenues 86,805 66,541 53,161 - ----------------------------------------------------------------------------------------------------------------------------- Total operating revenues 3,667,461 3,385,474 3,386,373 - ----------------------------------------------------------------------------------------------------------------------------- Operating Expenses: Operation -- Fuel 963,275 855,632 900,309 Purchased power -- Non-affiliates 164,881 93,204 92,998 Affiliates 184,014 180,563 150,897 Other 538,529 531,696 527,954 Maintenance 301,046 277,724 300,383 Depreciation and amortization 364,618 347,574 338,822 Taxes other than income taxes 209,673 204,645 193,049 - ----------------------------------------------------------------------------------------------------------------------------- Total operating expenses 2,726,036 2,491,038 2,504,412 - ----------------------------------------------------------------------------------------------------------------------------- Operating Income 941,425 894,436 881,961 Other Income (Expense): Interest income 38,167 55,896 68,553 Equity in earnings of unconsolidated subsidiaries (Note 5) 3,156 2,650 5,271 Other, net (7,909) (24,861) (37,050) - ----------------------------------------------------------------------------------------------------------------------------- Earnings Before Interest and Income Taxes 974,839 928,121 918,735 - ----------------------------------------------------------------------------------------------------------------------------- Interest and Other: Interest expense, net 251,663 245,235 285,940 Distributions on preferred securities of subsidiary (Note 8) 25,549 24,662 22,354 - ----------------------------------------------------------------------------------------------------------------------------- Total interest and other, net 277,212 269,897 308,294 - ----------------------------------------------------------------------------------------------------------------------------- Earnings Before Income Taxes 697,627 658,224 610,441 Income taxes (Note 7) 261,555 241,880 218,575 - ----------------------------------------------------------------------------------------------------------------------------- Net Income 436,072 416,344 391,866 Dividends on Preferred Stock 16,156 16,464 14,643 - ----------------------------------------------------------------------------------------------------------------------------- Net Income After Dividends on Preferred Stock $ 419,916 $ 399,880 $ 377,223 ============================================================================================================================= The accompanying notes are an integral part of these statements.
12 STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2000, 1999, and 1998 Alabama Power Company 2000 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------- 2000 1999 1998 - --------------------------------------------------------------------------------------------------------------------------------- (in thousands) Operating Activities: Net income $ 436,072 $ 416,344 $ 391,866 Adjustments to reconcile net income to net cash provided from operating activities -- Depreciation and amortization 412,998 403,332 425,167 Deferred income taxes and investment tax credits, net 66,166 29,039 79,430 Other, net (37,703) (12,661) (66,739) Changes in certain current assets and liabilities -- Receivables, net (125,652) 33,509 49,747 Fossil fuel stock 23,967 (1,344) (9,052) Materials and supplies (10,662) (17,968) 11,932 Accounts payable 107,702 (38,556) 26,583 Energy cost recovery, retail (69,190) (97,869) (95,427) Other 23,336 5,930 (9,803) - ---------------------------------------------------------------------------------------------------------------------------------- Net cash provided from operating activities 827,034 719,756 803,704 - ---------------------------------------------------------------------------------------------------------------------------------- Investing Activities: Gross property additions (870,581) (809,044) (610,132) Other (49,414) (72,218) (52,940) - ---------------------------------------------------------------------------------------------------------------------------------- Net cash used for investing activities (919,995) (881,262) (663,072) - ---------------------------------------------------------------------------------------------------------------------------------- Financing Activities: Increase (decrease) in notes payable, net 184,519 96,824 (306,882) Proceeds -- Other long-term debt 250,000 751,650 1,462,990 Preferred securities - 50,000 - Preferred stock - - 200,000 Capital contributions from parent company 204,371 204,347 30,000 Redemptions -- First mortgage bonds (111,009) (470,000) (771,108) Other long-term debt (5,987) (104,836) (107,776) Preferred stock - (50,000) (88,000) Payment of preferred stock dividends (16,110) (15,788) (15,596) Payment of common stock dividends (417,100) (399,600) (367,100) Other (951) (15,864) (66,869) - ---------------------------------------------------------------------------------------------------------------------------------- Net cash provided from financing activities 87,733 46,733 (30,341) - ---------------------------------------------------------------------------------------------------------------------------------- Net Change in Cash and Cash Equivalents (5,228) (114,773) 110,291 Cash and Cash Equivalents at Beginning of Period 19,475 134,248 23,957 - ---------------------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Period $ 14,247 $ 19,475 $ 134,248 ================================================================================================================================== Supplemental Cash Flow Information: Cash paid during the period for -- Interest (net of amount capitalized) $237,066 $229,305 $234,360 Income taxes (net of refunds) 175,303 170,121 188,942 - ---------------------------------------------------------------------------------------------------------------------------------- The accompanying notes are an integral part of these statements.
13 BALANCE SHEETS At December 31, 2000 and 1999 Alabama Power Company 2000 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------- Assets 2000 1999 - --------------------------------------------------------------------------------------------------------------------------------- (in thousands) Current Assets: Cash and cash equivalents $ 14,247 $ 19,475 Receivables -- Customer accounts receivable 337,870 265,900 Under-recovered retail fuel clause revenue 237,817 168,627 Other accounts and notes receivable 60,315 42,137 Affiliated companies 95,704 40,083 Accumulated provision for uncollectible accounts (6,237) (4,117) Refundable income taxes - 17,997 Fossil fuel stock, at average cost 60,615 84,582 Materials and supplies, at average cost 178,299 167,637 Other 52,624 46,011 - --------------------------------------------------------------------------------------------------------------------------------- Total current assets 1,031,254 848,332 - --------------------------------------------------------------------------------------------------------------------------------- Property, Plant, and Equipment: In service 12,431,575 11,783,078 Less accumulated provision for depreciation 5,107,822 4,901,384 - --------------------------------------------------------------------------------------------------------------------------------- 7,323,753 6,881,694 Nuclear fuel, at amortized cost 94,050 106,836 Construction work in progress 744,974 715,153 - --------------------------------------------------------------------------------------------------------------------------------- Total property, plant, and equipment 8,162,777 7,703,683 - --------------------------------------------------------------------------------------------------------------------------------- Other Property and Investments: Equity investments in unconsolidated subsidiaries (Note 5) 38,623 34,891 Nuclear decommissioning trusts 313,895 286,653 Other 13,612 12,156 - --------------------------------------------------------------------------------------------------------------------------------- Total other property and investments 366,130 333,700 - --------------------------------------------------------------------------------------------------------------------------------- Deferred Charges and Other Assets: Deferred charges related to income taxes (Note 7) 345,550 330,405 Prepaid pension costs 268,259 213,971 Debt expense, being amortized 8,758 9,563 Premium on reacquired debt, being amortized 76,020 83,895 Department of Energy assessments 24,588 27,685 Other 95,772 97,470 - --------------------------------------------------------------------------------------------------------------------------------- Total deferred charges and other assets 818,947 762,989 - --------------------------------------------------------------------------------------------------------------------------------- Total Assets $10,379,108 $9,648,704 ================================================================================================================================= The accompanying notes are an integral part of these balance sheets.
14 BALANCE SHEETS At December 31, 2000 and 1999 Alabama Power Company 2000 Annual Report
- ------------------------------------------------------------------------------------------------------------------------------ Liabilities and Stockholder's Equity 2000 1999 - ------------------------------------------------------------------------------------------------------------------------------ (in thousands) Current Liabilities: Securities due within one year (Note 10) $ 844 $ 100,943 Notes payable 281,343 96,824 Accounts payable -- Affiliated 124,534 91,315 Other 209,205 140,842 Customer deposits 36,814 31,704 Taxes accrued -- Income taxes 65,505 100,569 Other 19,471 18,295 Interest accrued 33,186 26,365 Vacation pay accrued 31,711 30,112 Other 97,743 84,267 - ------------------------------------------------------------------------------------------------------------------------------ Total current liabilities 900,356 721,236 - ------------------------------------------------------------------------------------------------------------------------------ Long-term debt (See accompanying statements) 3,425,527 3,190,378 - ------------------------------------------------------------------------------------------------------------------------------ Deferred Credits and Other Liabilities: Accumulated deferred income taxes (Note 7) 1,401,424 1,240,344 Deferred credits related to income taxes (Note 7) 222,485 265,102 Accumulated deferred investment tax credits 249,280 260,367 Employee benefits provisions 84,816 82,298 Prepaid capacity revenues (Note 6) 58,377 79,703 Other 176,559 155,901 - ------------------------------------------------------------------------------------------------------------------------------ Total deferred credits and other liabilities 2,192,941 2,083,715 - ------------------------------------------------------------------------------------------------------------------------------ Company obligated mandatorily redeemable preferred securities of subsidiary trusts holding company junior subordinated notes (See accompanying statements) (Note 8) 347,000 347,000 - ------------------------------------------------------------------------------------------------------------------------------ Cumulative preferred stock (See accompanying statements) 317,512 317,512 - ------------------------------------------------------------------------------------------------------------------------------ Common stockholder's equity (See accompanying statements) 3,195,772 2,988,863 - ------------------------------------------------------------------------------------------------------------------------------ Total Liabilities and Stockholder's Equity $10,379,108 $9,648,704 ============================================================================================================================== The accompanying notes are an integral part of these balance sheets.
15 STATEMENTS OF CAPITALIZATION At December 31, 2000 and 1999 Alabama Power Company 2000 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------- 2000 1999 2000 1999 - ---------------------------------------------------------------------------------------------------------------------------------- (in thousands) (percent of total) Long-Term Debt: First mortgage bonds -- Maturity Interest Rates -------- -------------- March 1, 2000 6.00% $ - $ 100,000 2023 through 2024 7.30% - 9.00% 488,991 500,000 - ---------------------------------------------------------------------------------------------------------------------------------- Total first mortgage bonds 488,991 600,000 - ---------------------------------------------------------------------------------------------------------------------------------- Senior notes -- 5.35% due November 15, 2003 156,200 156,200 7.850% due May 15, 2003 250,000 - 7.125% due August 15, 2004 250,000 250,000 5.49% due November 1, 2005 225,000 225,000 7.125% due October 1, 2007 200,000 200,000 5.375% due October 1, 2008 160,000 160,000 6.25% to 7.125% due 2010-2048 1,202,581 1,207,622 - ---------------------------------------------------------------------------------------------------------------------------------- Total senior notes 2,443,781 2,198,822 - ---------------------------------------------------------------------------------------------------------------------------------- Other long-term debt -- Pollution control revenue bonds -- Collateralized: 5.50% due 2024 24,400 24,400 Variable rates (4.73% to 5.05% at 1/1/01) due 2015-2017 89,800 89,800 Non-collateralized: 6.69% due 2021 65,000 - Variable rates (3.50% to 5.30% at 1/1/01) due 2021-2028 360,940 425,940 - ---------------------------------------------------------------------------------------------------------------------------------- Total other long-term debt (Note 9) 540,140 540,140 - ---------------------------------------------------------------------------------------------------------------------------------- Capitalized lease obligations 4,165 5,111 - ---------------------------------------------------------------------------------------------------------------------------------- Unamortized debt premium (discount), net (50,706) (52,752) - ---------------------------------------------------------------------------------------------------------------------------------- Total long-term debt (annual interest requirement -- $179.6 million) 3,426,371 3,291,321 Less amount due within one year 844 100,943 - ---------------------------------------------------------------------------------------------------------------------------------- Long-term debt excluding amount due within one year $3,425,527 $3,190,378 46.9% 46.6% - ----------------------------------------------------------------------------------------------------------------------------------
16 STATEMENTS OF CAPITALIZATION (continued) At December 31, 2000 and 1999 Alabama Power Company 2000 Annual Report
- ---------------------------------------------------------------------------------------------------------------------------------- 2000 1999 2000 1999 - ---------------------------------------------------------------------------------------------------------------------------------- (in thousands) (percent of total) Company Obligated Mandatorily Redeemable Preferred Securities: (Note 8) $25 liquidation value -- 7.375% $ 97,000 $ 97,000 7.60% 200,000 200,000 Auction rate (6.52% at 1/1/01) 50,000 50,000 - ---------------------------------------------------------------------------------------------------------------------------------- Total (annual distribution requirement -- $25.6 million) 347,000 347,000 4.8 5.1 - ---------------------------------------------------------------------------------------------------------------------------------- Cumulative Preferred Stock: $100 par or stated value -- 4.20% to 4.92% 47,512 47,512 $25 par or stated value -- 5.20% to 5.83% 200,000 200,000 Auction rates -- at 1/1/01 5.14% to 5.25% 70,000 70,000 - ---------------------------------------------------------------------------------------------------------------------------------- Total (annual dividend requirement -- $16.5 million) 317,512 317,512 4.4 4.6 - ---------------------------------------------------------------------------------------------------------------------------------- Common Stockholder's Equity: Common stock, par value $40 per share -- Authorized - 6,000,000 shares Outstanding - 5,608,955 shares in 2000 and 1999 Par value 224,358 224,358 Paid-in capital 1,743,363 1,538,992 Premium on Preferred Stock 99 99 Retained earnings 1,227,952 1,225,414 - ---------------------------------------------------------------------------------------------------------------------------------- Total common stockholder's equity 3,195,772 2,988,863 43.9 43.7 - ---------------------------------------------------------------------------------------------------------------------------------- Total Capitalization $7,285,811 $6,843,753 100.0% 100.0% ================================================================================================================================== The accompanying notes are an integral part of these statements.
17 STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2000, 1999, and 1998 Alabama Power Company 2000 Annual Report
- --------------------------------------------------------------------------------------------------------------------------- Premium on Common Paid-In Preferred Retained Stock Capital Stock Earnings Total - --------------------------------------------------------------------------------------------------------------------------- (in thousands) Balance at January 1, 1998 $224,358 $1,304,645 $99 $1,221,467 $2,750,569 Net income after dividends on preferred stock - - - 377,223 377,223 Capital contributions from parent company - 30,000 - - 30,000 Cash dividends on common stock - - - (367,100) (367,100) Other - - - (6,625) (6,625) - ---------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1998 224,358 1,334,645 99 1,224,965 2,784,067 Net income after dividends on preferred stock - - - 399,880 399,880 Capital contributions from parent company - 204,347 - - 204,347 Cash dividends on common stock - - - (399,600) (399,600) Other - - - 169 169 - ---------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 224,358 1,538,992 99 1,225,414 2,988,863 Net income after dividends on preferred stock - - - 419,916 419,916 Capital contributions from parent company - 204,371 - - 204,371 Cash dividends on common stock - - - (417,100) (417,100) Other - - - (278) (278) - ---------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2000 $224,358 $1,743,363 $99 $1,227,952 $3,195,772 ============================================================================================================================ The accompanying notes are an integral part of these statements.
18 NOTES TO FINANCIAL STATEMENTS Alabama Power Company 2000 Annual Report 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Alabama Power Company (the Company) is a wholly owned subsidiary of Southern Company, which is the parent company of five integrated Southeast utilities, a system service company (SCS), Southern Communications Services (Southern LINC), Southern Company Energy Solutions, Southern Nuclear Operating Company (Southern Nuclear), Mirant Corporation--formerly Southern Energy, Inc.-- and other direct and indirect subsidiaries. The integrated Southeast utilities --Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Savannah Electric and Power Company-- provide electric service in four states. Contracts among the integrated Southeast utilities - related to jointly-owned generating facilities, interconnecting transmission lines, and the exchange of electric power -- are regulated by the Federal Energy Regulatory Commission (FERC) and/or the Securities and Exchange Commission (SEC). SCS provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern LINC provides digital wireless communications services to the integrated Southeast utilities and also markets these services to the public within the Southeast. Southern Company Energy Solutions develops new business opportunities related to energy products and services. Southern Nuclear provides services to Southern Company's nuclear power plants. Mirant acquires, develops, builds, owns, and operates power production and delivery facilities and provides a broad range of energy-related services to utilities and industrial companies in selected countries around the world. Mirant businesses include independent power projects, integrated utilities, a distribution company, and energy trading and marketing businesses outside the southeastern United States. Southern Company is registered as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both Southern Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Company is also subject to regulation by the FERC and the Alabama Public Service Commission (APSC). The Company follows accounting principles generally accepted in the United States and complies with the accounting policies and practices prescribed by its respective regulatory commissions. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform with current year presentation. Related-Party Transactions The Company has an agreement with SCS under which the following services are rendered to the Company at cost: general and design engineering, purchasing, accounting and statistical, finance and treasury, tax, information resources, marketing, auditing, insurance and pension administration, human resources, systems and procedures, and other services with respect to business and operations and power pool transactions. Costs for these services amounted to $187 million, $218 million, and $201 million during 2000, 1999, and 1998, respectively. The Company also has an agreement with Southern Nuclear to operate Plant Farley and provide the following nuclear-related services at cost: general executive and advisory services; general operations, management and technical services; administrative services including procurement, accounting, statistical, and employee relations; and other services with respect to business and operations. Costs for these services amounted to $148 million, $135 million, and $137 million during 2000, 1999, and 1998, respectively. Regulatory Assets and Liabilities The Company is subject to the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. 19 NOTES (continued) Alabama Power Company 2000 Annual Report Regulatory assets and (liabilities) reflected in the Balance Sheets at December 31 relate to the following: 2000 1999 ----------------------- (in millions) Deferred income tax charges $ 346 $ 330 Deferred income tax credits (222) (265) Premium on reacquired debt 76 84 Department of Energy assessments 25 28 Vacation pay 32 30 Natural disaster reserve (18) (19) Other, net 30 59 - ---------------------------------------------------------------- Total $ 269 $ 247 ================================================================ In the event that a portion of the Company's operations is no longer subject to the provisions of FASB Statement No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair values. Revenues and Fuel Costs The Company currently operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the state of Alabama, and to wholesale customers in the southeast. Revenues are recognized as services are rendered. Unbilled revenues are accrued at the end of each fiscal period. Fuel revenues have no effect on net income because they represent the recording of revenues to offset fuel expenses, including the fuel component of purchased energy. Fuel rates billed to customers are designed to fully recover fluctuating fuel costs over a period of time. Higher natural gas prices and decreased hydro production combined with increased costs of purchased power have resulted in a large under-recovery of fuel costs at December 31, 2000. Effective January 2001, the Company's fuel rate was increased to address this under-recovery. The Company expects to significantly reduce this balance over a three-year period. The Company has a diversified base of customers. No single customer or industry comprises 10 percent or more of revenues. For all periods presented, uncollectible accounts continue to average less than 1 percent of revenues. Fuel expense includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. Total charges for nuclear fuel included in fuel expense amounted to $61 million in 2000, $63 million in 1999, and $59 million in 1998. The Company has a contract with the U.S. Department of Energy (DOE) that provides for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in January 1998 as required by the contract, and the Company is pursuing legal remedies against the government for breach of contract. Sufficient fuel storage capacity is available at Plant Farley to maintain full-core discharge capability until the refueling outage scheduled in 2006 for Farley Unit 1 and the refueling outage scheduled in 2008 for Farley Unit 2. Procurement of on-site dry spent fuel storage capacity at Plant Farley is in progress, with the intent to place the capacity in operation as early as 2005. Also, the Energy Policy Act of 1992 required the establishment of a Uranium Enrichment Decontamination and Decommissioning Fund, which is funded in part by a special assessment on utilities with nuclear plants. This assessment is being paid over a 15-year period, which began in 1993. This fund will be used by the DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The law provides that utilities will recover these payments in the same manner as any other fuel expense. The Company estimates its remaining liability under this law to be approximately $25 million at December 31, 2000. This obligation is recognized in the accompanying Balance Sheets. Depreciation and Nuclear Decommissioning Depreciation of the original cost of depreciable utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.2 percent in 2000, 1999 and 1998. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its cost -- together with the cost of removal, less salvage -- is charged to accumulated provision for depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation expense includes an amount for the expected cost of decommissioning nuclear facilities and removal of other facilities. 20 NOTES (continued) Alabama Power Company 2000 Annual Report The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial nuclear power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. The Company has established external trust funds to comply with the NRC's regulations. Amounts previously recorded in internal reserves are being transferred into the external trust funds over periods approved by the APSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC to ensure that -- over time -- the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC. Site study cost is the estimate to decommission the facility as of the site study year, and ultimate cost is the estimate to decommission the facility as of retirement date. The estimated costs of decommissioning -- both site study costs and ultimate costs - based on the most current study for Plant Farley were as follows: Site study basis (year) 1998 Decommissioning periods: Beginning year 2017 Completion year 2031 ------------------------------------------------------------- (in millions) Site study costs: Radiated structures $ 629 Non-radiated structures 60 ------------------------------------------------------------- Total $ 689 ============================================================= (in millions) Ultimate costs: Radiated structures $1,868 Non-radiated structures 178 ------------------------------------------------------------- Total $2,046 ============================================================= The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making estimates. Annual provisions for nuclear decommissioning are based on an annuity method as approved by the APSC. The amount expensed in 2000 and fund balances as of December 31, 2000 were: (in millions) Amount expensed in 2000 $ 18 ---------------------------------------------------------- Accumulated provisions: External trust funds, at fair value $314 Internal reserves 38 ---------------------------------------------------------- Total $352 ========================================================== All of the Company's decommissioning costs are approved for recovery by the APSC through the ratemaking process. Significant assumptions include an estimated inflation rate of 4.5 percent and an estimated trust earnings rate of 7.0 percent. The Company expects the APSC to periodically review and adjust, if necessary, the amounts collected in rates for the anticipated cost of decommissioning. Income Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits utilized are deferred and amortized to income over the average lives of the related property. Allowance For Funds Used During Construction (AFUDC) AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. While cash is not realized currently from such allowance, it increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation expense. The amount of AFUDC capitalized was $43 million in 2000, $23 million in 1999, and $9 million in 1998. The composite rate used to determine the amount of allowance was 9.6 percent in 2000, 8.8 percent in 1999, and 9.0 percent in 1998. AFUDC, net of income tax, as a percent of net income after dividends on preferred stock was 8.4 percent in 2000, 4.7 percent in 1999, and 1.8 percent in 1998. 21 NOTES (continued) Alabama Power Company 2000 Annual Report Property, Plant, and Equipment Property, plant, and equipment is stated at original cost. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the estimated cost of funds used during construction. The cost of maintenance, repairs and replacement of minor items of property is charged to maintenance expense. The cost of replacements of property --exclusive of minor items of property -- is capitalized. Financial Instruments The Company uses derivative financial instruments to hedge exposures to fluctuations in foreign currency exchange rates and certain commodity prices. Gains and losses on qualifying hedges are deferred and recognized either in income or as an adjustment to the carrying amount of the hedged item when the transaction occurs. The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. The Company is unaware of any counterparties that will fail to meet their obligations. The Company has firm purchase commitments for equipment that require payment in euros. As a hedge against fluctuations in the exchange rate for euros, the Company entered into forward currency swaps. The notional amount is 16 million euros maturing in 2001 through 2002. At December 31, 2000, the unrecognized gain on these swaps was approximately $1 million. Other Company financial instruments for which the carrying amount did not equal fair value at December 31 are as follows: Carrying Fair Amount Value ------------------------- (in millions) Long-term debt: At December 31, 2000 $3,422 $3,375 At December 31, 1999 3,286 3,045 Preferred Securities: At December 31, 2000 347 344 At December 31, 1999 347 299 -------------------------------------------------------------- The fair value for long-term debt and preferred securities was based on either closing market prices or closing prices of comparable instruments. Cash and Cash Equivalents For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. Materials and Supplies Generally, materials and supplies include the cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. Natural Disaster Reserve In accordance with an APSC order the Company has established a Natural Disaster Reserve. The Company is allowed to accrue $250 thousand per month, until the maximum accumulated provision of $32 million is attained. Higher accruals to restore the reserve to its authorized level are allowed whenever the balance in the reserve declines below $22.4 million. At December 31, 2000, the reserve balance was $18 million. 2. RETIREMENT BENEFITS The Company has defined benefit, trusteed, pension plans that cover substantially all employees. The Company provides certain medical care and life insurance benefits for retired employees. Substantially all employees may become eligible for such benefits when they retire. The Company funds trusts to the 22 NOTES (continued) Alabama Power Company 2000 Annual Report extent deductible under federal income tax regulations or to the extent required by the APSC and FERC. In late 2000, the Company adopted several pension and postretirement benefit plan changes that had the effect of increasing benefits to both current and future retirees. The effects of these changes will be to increase annual pension and postretirement benefits cost by approximately $8 million and $12 million, respectively. The measurement date for plan assets and obligations is September 30 of each year. The weighted average rates assumed in the actuarial calculations for both the pension and postretirement benefit plans were: 2000 1999 - ------------------------------------------------------------ Discount 7.50% 7.50% Annual salary increase 5.00 5.00 Long-term return on plan assets 8.50 8.50 - ------------------------------------------------------------ Pension Plan Changes during the year in the projected benefit obligations and in the fair value of plan assets were as follows: Projected Benefit Obligations --------------------------- 2000 1999 - --------------------------------------------------------------- (in millions) Balance at beginning of year $873 $868 Service cost 22 23 Interest cost 64 57 Benefits paid (51) (51) Actuarial gain and employee transfers (8) (24) - --------------------------------------------------------------- Balance at end of year $900 $873 =============================================================== Plan Assets --------------------------- 2000 1999 - --------------------------------------------------------------- (in millions) Balance at beginning of year $1,647 $1,461 Actual return on plan assets 302 245 Benefits paid (51) (51) Employee transfers 23 (8) - --------------------------------------------------------------- Balance at end of year $1,921 $1,647 =============================================================== The accrued pension costs recognized in the Balance Sheets were as follows: 2000 1999 - --------------------------------------------------------------- (in millions) Funded status $1,021 $ 774 Unrecognized transition obligation (21) (25) Unrecognized prior service cost 33 36 Unrecognized net actuarial gain (765) (571) - --------------------------------------------------------------- Prepaid asset recognized in the Balance Sheets $ 268 $ 214 =============================================================== Components of the pension plans' net periodic cost were as follows: 2000 1999 1998 - ------------------------------------------------------------------ (in millions) Service cost $ 23 $ 23 $ 22 Interest cost 64 57 59 Expected return on plan assets (119) (109) (102) Recognized net actuarial gain (20) (14) (16) Net amortization (2) (2) (2) - ------------------------------------------------------------------ Net pension income $(54) $ (45) $(39) ================================================================== Postretirement Benefits Changes during the year in the accumulated benefit obligations and in the fair value of plan assets were as follows: Accumulated Benefit Obligations --------------------------- 2000 1999 - ---------------------------------------------------------------- (in millions) Balance at beginning of year $264 $278 Service cost 4 5 Interest cost 19 18 Benefits paid (12) (10) Actuarial gain and employee transfers (11) (27) - --------------------------------------------------------------- Balance at end of year $264 $264 =============================================================== Plan Assets --------------------------- 2000 1999 - --------------------------------------------------------------- (in millions) Balance at beginning of year $161 $137 Actual return on plan assets 25 18 Employer contributions 18 16 Benefits paid (12) (10) - --------------------------------------------------------------- Balance at end of year $192 $161 =============================================================== 23 NOTES (continued) Alabama Power Company 2000 Annual Report The accrued postretirement costs recognized in the Balance Sheets were as follows: 2000 1999 - --------------------------------------------------------------- (in millions) Funded status $(72) $(103) Unrecognized transition obligation 49 53 Unrecognized net actuarial gain (35) (12) Fourth quarter contributions 4 8 - --------------------------------------------------------------- Accrued liability recognized in the Balance Sheets $(54) $ (54) =============================================================== Components of the plans' net periodic cost were as follows: 2000 1999 1998 - --------------------------------------------------------------- (in millions) Service cost $ 4 $ 5 $ 5 Interest cost 19 18 18 Expected return on plan assets (13) (11) (9) Net amortization 4 4 4 - --------------------------------------------------------------- Net postretirement cost $ 14 $ 16 $18 =============================================================== An additional assumption used in measuring the accumulated postretirement benefit obligations was a weighted average medical care cost trend rate of 7.29 percent for 2000, decreasing gradually to 5.50 percent through the year 2005, and remaining at that level thereafter. An annual increase or decrease in the assumed medical care cost trend rate of 1 percent would affect the accumulated benefit obligation and the service and interest cost components at December 31, 2000 as follows: 1 Percent 1 Percent Increase Decrease - --------------------------------------------------------------- (in millions) Benefit obligation $15 $14 Service and interest costs 1 1 =============================================================== Employee Savings Plan The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides a 75 percent matching contribution up to 6 percent of an employee's base salary. Total matching contributions made to the plan for the years 2000, 1999, and 1998 were $11 million, $10 million, and $10 million, respectively. Work Force Reduction Programs The Company has incurred costs for work force reduction programs totaling $2.6 million, $5.6 million and $19.4 million for the years 2000, 1999 and 1998, respectively. These costs were deferred and are being amortized in accordance with regulatory treatment. The unamortized balance of these costs was $1.4 million at December 31, 2000. 3. CONTINGENCIES AND REGULATORY MATTERS Environmental Litigation On November 3, 1999, the Environmental Protection Agency (EPA), brought a civil action against the Company in the U. S. District Court. The complaint alleges violations of the prevention of significant deterioration and new source review provision of the Clean Air Act with respect to coal-fired generating facilities at the Company's Plants Miller, Barry and Gorgas. The civil action requests penalties and injunctive relief, including an order requiring the installation of the best available control technology at the affected units. The Clean Air Act authorizes civil penalties of up to $27,500 per day, per violation at each generating unit. Prior to January 30, 1997, the penalty was $25,000 per day. The EPA concurrently issued to the Company a notice of violation relating to these specific facilities, as well as Plants Greene County and Gaston. In early 2000, the EPA filed a motion to amend its complaint to add the violations alleged in its notice of violation. The complaint and the notice of violation are similar to those brought against and issued to several other electric utilities. The complaint and the notice of violation allege that the Company failed to secure necessary permits or install additional pollution control equipment when performing maintenance and construction at coal burning plants constructed or under construction prior to 1978. On August 1, 2000, the U.S. District Court granted the Company's motion to dismiss for lack of jurisdiction in Georgia and granted SCS's motion to dismiss on the grounds that it neither owned nor operated the generating units involved in the proceedings. On January 12, 2001, the EPA re-filed its claims against the Company in federal district court in Birmingham, Alabama. The EPA did not include SCS in the new complaint. The Company believes that it complied with applicable laws and the EPA's 24 NOTES (continued) Alabama Power Company 2000 Annual Report regulations and interpretations in effect at the time the work in question took place. An adverse outcome of this matter could require substantial capital expenditures that cannot be determined at this time and possibly require payment of substantial penalties. This could affect future results of operations, cash flows, and possibly financial condition if such costs are not recovered through regulated rates. Retail Rate Adjustment Procedures The APSC has adopted rates that provide for periodic adjustments based upon the Company's earned return on end-of-period retail common equity. The rates also provide for adjustments to recognize the placing of new generating facilities into retail service. Both increases and decreases have been placed into effect since the adoption of these rates. The rate adjustment procedures allow a return on common equity range of 13.0 percent to 14.5 percent and limit increases or decreases in rates to 4 percent in any calendar year. There is a moratorium on any periodic retail rate increases (but not decreases) until July 2001. In December 1995, the APSC issued an order authorizing the Company to reduce balance sheet items -- such as plant and deferred charges -- at any time the Company's actual base rate revenues exceed the budgeted revenues. In April 1997, the APSC issued an additional order authorizing the Company to reduce balance sheet asset items. This order authorizes the reduction of such items up to an amount equal to five times the total estimated annual revenue reduction resulting from future rate reductions initiated by the Company. In 1998, the Company - in accordance with the 1995 rate order - recorded $33 million of additional amortization of premium on reacquired debt. The Company did not record any additional amounts in 2000 or 1999. In April 2000, the APSC approved an amendment to the Company's existing rate structure to provide for the recovery of retail costs associated with certified purchased power agreements. In November 2000, the APSC certified a seven-year purchased power agreement pertaining to 615 megawatts of the Company's wholesale generating facilities under construction in Autaugaville, Alabama, all of which will be delivered in 2003. In addition, the APSC certified a seven-year purchased power agreement with a third party for approximately 630 megawatts; one half of the power will be delivered in 2003 while the remaining half is scheduled for delivery in 2004. The Company's ratemaking procedures will remain in effect until the APSC votes to modify or discontinue them. 4. FINANCING AND COMMITMENTS Construction Program To the extent possible, the Company's construction program is expected to be financed primarily from internal sources. Short-term debt is often utilized and the amounts available are discussed below. The Company may issue additional long-term debt and preferred securities for debt maturities, redeeming higher-cost securities, and meeting additional capital requirements. The Company currently estimates property additions to be $735 million in 2001, $891 million in 2002, and $625 million in 2003. The Company is constructing 1,230 megawatts of wholesale generating facilities in Autaugaville, Alabama to begin operation in 2003. Half of this capacity has been certified by the APSC to serve the Company's retail customers for seven years. The other half of the capacity will be sold into the wholesale market and will not affect retail rates. During 2001, the Company plans to transfer these generating facilities to Southern Power Company (SPC), the new wholesale subsidiary formed by Southern Company. If the Company transfers wholesale generation assets to SPC as planned, construction expenditures for the years 2001 through 2003 will be $598 million, $591 million and $583 million, respectively. During 2001, the Company expects to complete the replacement of the steam generators at Plant Farley, as well as the construction of new generating capacity at Plant Barry. In addition, significant construction will continue related to transmission and distribution facilities and the upgrading of generating plants, including the expenditures necessary to comply with environmental regulation. The capital budget is subject to periodic review and revision, and actual capital costs incurred may vary from estimates because of changes in such factors as: business conditions; environmental regulations; nuclear plant 25 NOTES (continued) Alabama Power Company 2000 Annual Report regulations; load projections; the cost and efficiency of construction labor, equipment, and materials; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Financing The ability of the Company to finance its capital budget depends on the amount of funds generated internally and the funds it can raise by external financing. The Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from internal sources. However, the type and timing of any financings - if needed - will depend on market conditions and regulatory approval. In recent years, financings primarily have utilized unsecured debt and trust preferred securities. Bank Credit Arrangements The Company maintains committed lines of credit in the amount of $925 million (including $418 million of such lines which are dedicated to funding purchase obligations relating to variable rate pollution control bonds). Of these lines, $535 million expire at various times during 2001 and $390 million expire in 2004. In certain cases, such lines require payment of a commitment fee based on the unused portion of the commitment or the maintenance of compensating balances with the banks. Because the arrangements are based on an average balance, the Company does not consider any of its cash balances to be restricted as of any specific date. Moreover, the Company borrows from time to time pursuant to arrangements with banks for uncommitted lines of credit. At December 31, 2000, the Company had regulatory approval to have outstanding up to $750 million of short-term borrowings. Assets Subject to Lien The Company's mortgage, as amended and supplemented, securing the first mortgage bonds issued by the Company, constitutes a direct lien on substantially all of the Company's fixed property and franchises. Purchased Power Commitments The Company has entered into various long-term commitments for the purchase of electricity. Estimated total long-term obligations at December 31, 2000 were as follows: Year Commitments - ---- --------------- (in millions) 2001 $ - 2002 - 2003 16 2004 34 2005 37 2006 and beyond 180 - ----------------------------------------------------------- Total commitments $ 267 =========================================================== Fuel Commitments To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement of fossil and nuclear fuel. In most cases, these contracts contain provisions for price escalations, minimum purchase levels and other financial commitments. Total estimated long-term obligations at December 31, 2000, were as follows: Year Commitments - ---- --------------- (in millions) 2001 $ 998 2002 841 2003 722 2004 669 2005 525 2006 - 2024 2,287 - ----------------------------------------------------------- Total commitments $6,042 =========================================================== 26 NOTES (continued) Alabama Power Company 2000 Annual Report Operating Leases The Company has entered into coal rail car rental agreements with various terms and expiration dates. These expenses totaled $20.9 million in 2000, $17.8 million in 1999, and $5.8 million in 1998. At December 31, 2000, estimated minimum rental commitments for noncancellable operating leases were as follows: Year Commitments - ---- ------------- (in millions) 2001 $ 22.2 2002 21.6 2003 21.2 2004 18.2 2005 15.5 2006 - 2017 44.7 - ----------------------------------------------------------- Total minimum payments $143.4 =========================================================== 5. JOINT OWNERSHIP AGREEMENTS The Company and Georgia Power Company own equally all of the outstanding capital stock of Southern Electric Generating Company (SEGCO), which owns electric generating units with a total rated capacity of 1,020 megawatts, together with associated transmission facilities. The capacity of these units is sold equally to the Company and Georgia Power Company under a contract which, in substance, requires payments sufficient to provide for the operating expenses, taxes, interest expense and a return on equity, whether or not SEGCO has any capacity and energy available. The term of the contract extends automatically for two-year periods, subject to either party's right to cancel upon two year's notice. The Company's share of expenses totaled $85 million in 2000, $92 million in 1999 and $74 million in 1998, and is included in "Purchased power from affiliates" in the Statements of Income. In addition, the Company has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO's generating units, pursuant to which $24.5 million principal amount of pollution control revenue bonds are outstanding. Georgia Power Company has agreed to reimburse the Company for the pro rata portion of such obligation corresponding to its then proportionate ownership of stock of SEGCO if the Company is called upon to make such payment under its guaranty. At December 31, 2000, the capitalization of SEGCO consisted of $51 million of equity and $78 million of long-term debt on which the annual interest requirement is $5.3 million. SEGCO paid dividends totaling $5.1 million in 2000, $4.3 million in 1999, and $8.7 million in 1998, of which one-half of each was paid to the Company. SEGCO's net income was $5.9 million, $5.4 million, and $7.5 million for 2000, 1999 and 1998, respectively. The Company's percentage ownership and investment in jointly-owned generating plants at December 31, 2000, is as follows: Total Megawatt Company Facility (Type) Capacity Ownership --------------------- ------------ ------------- Greene County 500 60.00% (1) (coal) Plant Miller Units 1 and 2 1,320 91.84% (2) (coal) ----------------------------------------------------------- (1) Jointly owned with an affiliate, Mississippi Power Company. (2) Jointly owned with Alabama Electric Cooperative, Inc. Company Accumulated Facility Investment Depreciation --------------------- -------------- --------------- (in millions) Greene County $100 $ 46 Plant Miller Units 1 and 2 743 312 ---------------------------------------------------------- 6. LONG-TERM POWER SALES AGREEMENTS General The Company and the other integrated utility subsidiaries of Southern Company have entered into long-term contractual agreements for the sale of capacity and energy to certain non-affiliated utilities located outside the system's service area. These agreements -- expiring at various dates discussed below -- are firm and pertain to capacity related to specific generating units. Because the energy is generally sold at cost under these agreements, profitability is primarily affected by revenues from capacity sales. The Company's capacity revenues amounted to $127 million in 2000, $122 million in 1999, and $142 million in 1998. Unit power from Plant Miller is being sold to Florida Power Corporation (FPC), Florida Power & Light Company (FP&L), and Jacksonville Electric Authority 27 NOTES (continued) Alabama Power Company 2000 Annual Report (JEA). Under these agreements, approximately 1,235 megawatts of capacity are scheduled to be sold through 2001. Thereafter, these sales will remain at that approximate level -- unless reduced by FP&L, FPC, and JEA for the periods after 2001 with a minimum of three years notice -- until the expiration of the contracts in 2010. No notices of cancellation have been received. Alabama Municipal Electric Authority (AMEA) Capacity Contracts In August 1986, the Company entered into a firm power sales contract with AMEA entitling AMEA to scheduled amounts of capacity (to a maximum 100 megawatts) for a period of 15 years commencing September 1, 1986 (1986 Contract). In October 1991, the Company entered into a second firm power sales contract with AMEA entitling AMEA to scheduled amounts of additional capacity (to a maximum 80 megawatts) for a period of 15 years commencing October 1, 1991 (1991 Contract). In both contracts the power will be sold to AMEA for its member municipalities that previously were served directly by the Company as wholesale customers. Under the terms of the contracts, the Company received payments from AMEA representing the net present value of the revenues associated with the respective capacity entitlements, discounted at effective annual rates of 9.96 percent and 11.19 percent for the 1986 and 1991 contracts, respectively. These payments are being recognized as operating revenues and the discounts are being amortized to other interest expense as scheduled capacity is made available over the terms of the contracts. In order to secure AMEA's advance payments and the Company's performance obligation under the contracts, the Company issued and delivered to an escrow agent first mortgage bonds representing the maximum amount of liquidated damages payable by the Company in the event of a default under the contracts. No principal or interest is payable on such bonds unless and until a default by the Company occurs. As the liquidated damages decline under the contracts, a portion of the bonds equal to the decreases is returned to the Company. At December 31, 2000, $61.3 million of such bonds were held by the escrow agent under the contracts. 7. INCOME TAXES At December 31, 2000, the tax-related regulatory assets and liabilities were $346 million and $222 million, respectively. These assets are attributable to tax benefits flowed through to customers in prior years and to taxes applicable to capitalized interest. These liabilities are attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized investment tax credits. Details of the income tax provisions are as follows: 2000 1999 1998 -------------------------------- (in millions) Total provision for income taxes: Federal -- Current $168 $194 $123 Deferred 60 24 72 - ----------------------------------------------------------------- 228 218 195 - ----------------------------------------------------------------- State -- Current 27 19 16 Deferred 7 5 7 - ------------------------------------------------------ ---------- 34 24 23 - ----------------------------------------------------------------- Total $262 $242 $218 ================================================================= The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: 2000 1999 ------------------ (in millions) Deferred tax liabilities: Accelerated depreciation $ 992 $884 Property basis differences 405 419 Fuel cost adjustment 93 65 Premium on reacquired debt 30 31 Pensions 75 60 Other 12 11 - ----------------------------------------------------------------- Total 1,607 1,470 - ----------------------------------------------------------------- Deferred tax assets: Capacity prepayments 18 24 Other deferred costs 14 25 Postretirement benefits 24 22 Unbilled revenue 23 13 Other 81 63 - ----------------------------------------------------------------- Total 160 147 - ----------------------------------------------------------------- Net deferred tax liabilities 1,447 1,323 Portion included in current liabilities, net (46) (83) - ----------------------------------------------------------------- Accumulated deferred income taxes in the Balance Sheets $1,401 $1,240 ================================================================= 28 NOTES (continued) Alabama Power Company 2000 Annual Report Deferred investment tax credits are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the Statements of Income. Credits amortized in this manner amounted to $11 million in 2000, 1999, and 1998. At December 31, 2000, all investment tax credits available to reduce federal income taxes payable had been utilized. A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: 2000 1999 1998 -------------------------- Federal statutory rate 35.0% 35.0% 35.0% State income tax, net of federal deduction 3.1 2.4 2.5 Non-deductible book depreciation 1.4 1.6 1.5 Differences in prior years' deferred and current tax rates (1.3) (1.3) (1.6) Other (0.7) (0.9) (1.6) - --------------------------------------------------------------- Effective income tax rate 37.5% 36.8% 35.8% =============================================================== Southern Company files a consolidated federal and certain state income tax returns. Under a joint consolidated income tax agreement, each subsidiary's current and deferred tax expense is computed on a stand-alone basis. 8. COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES Statutory business trusts formed by the Company, of which the Company owns all the common securities, have issued mandatorily redeemable preferred securities as follows: Date of Maturity Issue Amount Rate Notes Date --------------------------------------------------- (millions) (millions) Trust I 1/1996 $ 97 7.375% $100 3/2026 Trust II 1/1997 200 7.60 206 12/2036 Trust III 2/1999 50 Auction 52 2/2029 Substantially all of the assets of each trust are junior subordinated notes issued by the Company in the respective approximate principal amounts set forth above. The distribution rate of Trust III's auction rate securities was 6.52% at January 1, 2001. The Company considers that the mechanisms and obligations relating to the preferred securities, taken together, constitute a full and unconditional guarantee by the Company of the Trusts' payment obligations with respect to the preferred securities. The Trusts are subsidiaries of the Company and, accordingly, are consolidated in the Company's financial statements. 9. OTHER LONG-TERM DEBT Pollution control obligations represent installment purchases of pollution control facilities financed by funds derived from sales by public authorities of revenue bonds. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. With respect to $114.2 million of such pollution control obligations, the Company has authenticated and delivered to the trustees a like principal amount of first mortgage bonds as security for its obligations under the installment purchase agreements. No principal or interest on these first mortgage bonds is payable unless and until a default occurs on the installment purchase agreements. In May 2000, the Company issued $250 million of unsecured senior notes. The proceeds of this issuance were used to repay short-term indebtedness. All of the Company's senior notes are, in effect, subordinated to all secured debt of the Company, including its first mortgage bonds. The estimated aggregate annual maturities of capitalized lease obligations through 2005 are as follows: $0.8 million in 2001, $0.9 million in 2002, $0.9 million in 2003, $1.0 million in 2004 and $0.1 million in 2005. 10. SECURITIES DUE WITHIN ONE YEAR A summary of the improvement fund requirements and scheduled maturities and redemptions of long-term debt due within one year at December 31 is as follows: 2000 1999 ------------------------ (in thousands) First mortgage bond maturities and redemptions $ - $100,000 Other long-term debt maturities (Note 9) 844 943 ------------------------------------------------------------- Total long-term debt due within one year $844 $100,943 ============================================================= 29 NOTES (continued) Alabama Power Company 2000 Annual Report The annual first mortgage bond improvement fund requirement is 1 percent of the aggregate principal amount of bonds of each series authenticated, so long as a portion of that series is outstanding, and may be satisfied by the deposit of cash and/or reacquired bonds, the certification of unfunded property additions, or a combination thereof. 11. NUCLEAR INSURANCE Under the Price-Anderson Amendments Act of 1988 (the Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to $9.5 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $200 million by private insurance, with the remaining coverage provided by a mandatory program of deferred premiums which could be assessed, after a nuclear incident, against all owners of nuclear reactors. The Company could be assessed up to $88 million per incident for each licensed reactor it operates but not more than an aggregate of $10 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is $176 million per incident but not more than an aggregate of $20 million to be paid for each incident in any one year. The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million for members' nuclear generating facilities. Additionally, the Company has policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. This excess insurance is also provided by NEIL. NEIL also covers the additional cost that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can be insured against increased costs of replacement power in an amount up to $3.5 million per week (starting 12 weeks after the outage) for one year and up to $2.8 million per week for the second and third years. Under each of the NEIL policies, members are subject to assessments if losses each year exceed the accumulated funds available to the insurer under that policy. The current maximum annual assessments for the Company under the three NEIL policies would be $17 million. For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its bond trustees as may be appropriate under the policies and applicable trust indentures. All retrospective assessments, whether generated for liability, property or replacement power may be subject to applicable state premium taxes. 12. COMMON STOCK DIVIDEND RESTRICTIONS The Company's first mortgage bond indenture contains various common stock dividend restrictions that remain in effect as long as the bonds are outstanding. At December 31, 2000, retained earnings of $796 million were restricted against the payment of cash dividends on common stock under terms of the mortgage indenture. 13. QUARTERLY FINANCIAL INFORMATION (Unaudited) Summarized quarterly financial data for 2000 and 1999 are as follows: Net Income After Dividends Quarter Operating Operating on Preferred Ended Revenues Income Stock - -------------------- ----------------------------------------- (in millions) March 2000 $ 746 $172 $ 68 June 2000 900 229 103 September 2000 1,137 390 209 December 2000 884 151 40 March 1999 $ 714 $162 $ 63 June 1999 823 209 93 September 1999 1,116 388 201 December 1999 733 136 43 - ----------------------------------------------------------------- The Company's business is influenced by seasonal weather conditions. 30 SELECTED FINANCIAL AND OPERATING DATA 1996-2000 Alabama Power Company 2000 Annual Report
- --------------------------------------------------------------------------------------------------------------------------------- 2000 1999 1998 1997 1996 - --------------------------------------------------------------------------------------------------------------------------------- Operating Revenues (in thousands) $3,667,461 $3,385,474 $3,386,373 $3,149,111 $3,120,775 Net Income after Dividends on Preferred Stock (in thousands) $419,916 $399,880 $377,223 $375,939 $371,490 Cash Dividends on Common Stock (in thousands) $417,100 $399,600 $367,100 $339,600 $347,500 Return on Average Common Equity (percent) 13.58 13.85 13.63 13.76 13.75 Total Assets (in thousands) $10,379,108 $9,648,704 $9,225,698 $8,812,867 $8,733,846 Gross Property Additions (in thousands) $870,581 $809,044 $610,132 $451,167 $425,024 - --------------------------------------------------------------------------------------------------------------------------------- Capitalization (in thousands): Common stock equity $3,195,772 $2,988,863 $2,784,067 $2,750,569 $2,714,277 Preferred stock 317,512 317,512 317,512 255,512 340,400 Company obligated mandatorily redeemable preferred securities 347,000 347,000 297,000 297,000 97,000 Long-term debt 3,425,527 3,190,378 2,646,566 2,473,202 2,354,006 - --------------------------------------------------------------------------------------------------------------------------------- Total (excluding amounts due within one year) $7,285,811 $6,843,753 $6,045,145 $5,776,283 $5,505,683 ================================================================================================================================- Capitalization Ratios (percent): Common stock equity 43.9 43.7 46.1 47.6 49.3 Preferred stock 4.4 4.6 5.3 4.4 6.2 Company obligated mandatorily redeemable preferred securities 4.8 5.1 4.9 5.2 1.7 Long-term debt 46.9 46.6 43.7 42.8 42.8 - --------------------------------------------------------------------------------------------------------------------------------- Total (excluding amounts due within one year) 100.0 100.0 100.0 100.0 100.0 ================================================================================================================================- Security Ratings: First Mortgage Bonds - Moody's A1 A1 A1 A1 A1 Standard and Poor's A A+ A+ A+ A+ Fitch AA-* AA- AA- AA- AA- Preferred Stock - Moody's a2 a2 a2 a2 a2 Standard and Poor's BBB+ A- A A A Fitch A* A A A+ A+ Unsecured Long-Term Debt - Moody's A2 A2 A2 A2 - Standard and Poor's A A A A - Fitch A+* A+ A+ A+ - ================================================================================================================================- Customers (year-end): Residential 1,132,410 1,120,574 1,106,217 1,092,161 1,073,559 Commercial 193,106 188,368 182,738 177,362 171,827 Industrial 4,819 4,897 5,020 5,076 5,100 Other 745 735 733 728 732 - --------------------------------------------------------------------------------------------------------------------------------- Total 1,331,080 1,314,574 1,294,708 1,275,327 1,251,218 ================================================================================================================================- Employees (year-end): 6,871 6,792 6,631 6,531 6,865 - --------------------------------------------------------------------------------------------------------------------------------- *Effective 1/22/01 the Fitch Security Ratings for First Mortgage Bonds, Preferred Stock, and Unsecured Long-Term Debt are A+, A-, and A respectively.
31 SELECTED FINANCIAL AND OPERATING DATA 1996-2000 (continued) Alabama Power Company 2000 Annual Report
- ----------------------------------------------------------------------------------------------------------------------------------- 2000 1999 1998 1997 1996 - ----------------------------------------------------------------------------------------------------------------------------------- Operating Revenues (in thousands): Residential $ 1,222,509 $1,145,646 $ 1,133,435 $ 997,507 $ 998,806 Commercial 854,695 807,098 779,169 724,148 696,453 Industrial 859,668 843,090 853,550 775,591 759,628 Other 15,835 15,283 14,523 13,563 13,729 - ----------------------------------------------------------------------------------------------------------------------------------- Total retail 2,952,707 2,811,117 2,780,677 2,510,809 2,468,616 Sales for resale - non-affiliates 461,730 415,377 448,973 431,023 391,669 Sales for resale - affiliates 166,219 92,439 103,562 161,795 216,620 - ----------------------------------------------------------------------------------------------------------------------------------- Total revenues from sales of electricity 3,580,656 3,318,933 3,333,212 3,103,627 3,076,905 Other revenues 86,805 66,541 53,161 45,484 43,870 - ----------------------------------------------------------------------------------------------------------------------------------- Total $3,667,461 $3,385,474 $3,386,373 $3,149,111 $3,120,775 ==================================================================================================================================- Kilowatt-Hour Sales (in thousands): Residential 16,771,821 15,699,081 15,794,543 14,336,408 14,593,761 Commercial 12,988,728 12,314,085 11,904,509 11,330,312 10,904,476 Industrial 22,101,407 21,942,889 21,585,117 20,727,912 19,999,258 Other 205,827 201,149 196,647 180,389 192,573 - ----------------------------------------------------------------------------------------------------------------------------------- Total retail 52,067,783 50,157,204 49,480,816 46,575,021 45,690,068 Sales for resale - non-affiliates 14,847,533 12,437,599 11,840,910 12,329,480 9,491,237 Sales for resale - affiliates 5,369,474 5,031,781 5,976,099 8,993,326 10,292,066 - ----------------------------------------------------------------------------------------------------------------------------------- Total 72,284,790 67,626,584 67,297,825 67,897,827 65,473,371 ==================================================================================================================================- Average Revenue Per Kilowatt-Hour (cents): Residential 7.29 7.30 7.18 6.96 6.84 Commercial 6.58 6.55 6.55 6.39 6.39 Industrial 3.89 3.84 3.95 3.74 3.80 Total retail 5.67 5.60 5.62 5.39 5.40 Sales for resale 3.11 2.91 3.10 2.78 3.07 Total sales 4.95 4.91 4.95 4.57 4.70 Residential Average Annual Kilowatt-Hour Use Per Customer 14,875 14,097 14,370 13,254 13,705 Residential Average Annual Revenue Per Customer $1,084.26 $1,028.76 $1,031.21 $922.21 $937.95 Plant Nameplate Capacity Ratings (year-end) (megawatts) 12,122 11,379 11,151 11,151 11,151 Maximum Peak-Hour Demand (megawatts): Winter 9,478 8,863 7,757 8,478 8,413 Summer 11,019 10,739 10,329 9,778 9,912 Annual Load Factor (percent) 59.3 59.7 62.9 62.7 61.3 Plant Availability (percent): Fossil-steam 89.4 80.4 85.6 86.3 86.6 Nuclear 88.3 91.0 80.2 88.8 90.5 - ----------------------------------------------------------------------------------------------------------------------------------- Source of Energy Supply (percent): Coal 63.0 64.1 65.3 65.7 67.0 Nuclear 16.9 17.8 16.3 17.9 18.5 Hydro 2.9 4.7 6.9 7.5 7.1 Oil and gas 4.9 1.1 1.5 0.7 0.4 Purchased power - From non-affiliates 4.6 4.5 3.3 2.4 2.4 From affiliates 7.7 7.8 6.7 5.8 4.6 - ----------------------------------------------------------------------------------------------------------------------------------- Total 100.0 100.0 100.0 100.0 100.0 ==================================================================================================================================-
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